Drilling riser elastic swivel for boundary layer control

ABSTRACT

The present invention relates to the marine drilling risers and other submerged hulls, and methods and apparatuses for reducing vibration and drag in the drilling risers when they are beset by ocean currents, for instance elastic swivel devices for use in orienting a riser in a desired direction for boundary layer control applications.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional Patent Application No. 61/177,612, filed May 12, 2009, entitled “DRILLING RISER ELASTIC SWIVEL AND BOUNDARY LAYER CONTROL,” the disclosure of which is hereby incorporated by reference in its entirety.

TECHNICAL FIELD

The present invention relates to the marine drilling risers and other submerged hulls, and methods and apparatuses for aiding in the positioning of risers and boundary layer control devices when they are beset by ocean currents using a generally sealed elastic or resilient swivel coupling.

BACKGROUND

Marine drilling risers and other submerged hulls, such as columns, SPARs, and semi-submersible drilling vessels, are subject to hydrodynamic drag forces and vortex-induced vibration (VIV) that may interfere with operation and cause equipment failure. A Boundary Layer Control (BLC) system, which is disclosed in U.S. Pat. Nos. 7,108,457, 6,349,664 and 6,148,751, incorporated herein by reference, may be used to counteract these drag and vibrational forces. However, such BLC systems generally are only effective when properly oriented with respect to an oncoming ocean current.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present invention will be readily understood by the written description along with reference to the accompanying drawings. Embodiments of the invention are illustrated by way of example and not by way of limitation in the accompanying drawings.

FIG. 1 illustrates three exemplary configurations of piping flex hoses on a specialized riser joint adapted for use with rotatable vertical risers as rotated, in accordance with various embodiments;

FIG. 2 illustrates an exemplary RES in both an external view (right side) and a cutaway view (left side), with the RES integrated as the lower part of a specialized riser joint, in accordance with various embodiments; and

FIG. 3 illustrates a detailed view of the two areas of the RES joint that are indicated in FIG. 2, in accordance with various embodiments.

DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION

In the following detailed description, reference is made to the accompanying drawings which form a part hereof, and in which are shown by way of illustration of examples or embodiments in which the disclosure may be practiced. It is to be understood that other embodiments may be utilized and structural or logical changes may be made without departing from the scope of the present disclosure. Therefore, the following detailed description is not to be taken in a limiting sense, and the scope of embodiments in accordance with the present disclosure is defined by the appended claims and their equivalents.

Various operations may be described as multiple discrete operations in turn, in a manner that may be helpful in understanding embodiments of the present disclosure; however, the order of description should not be construed to imply that these operations are order dependent.

The description may use perspective-based descriptions such as up/down, back/front, and top/bottom. Such descriptions are merely used to facilitate the discussion and are not intended to restrict the application of embodiments of the present disclosure.

The terms “coupled” and “connected,” along with their derivatives, may be used. It should be understood that these terms are not intended as synonyms for each other. Rather, in particular embodiments, “connected” may be used to indicate that two or more elements are in direct physical or electrical contact with each other. “Coupled” may mean that two or more elements are in direct physical or electrical contact. However, “coupled” may also mean that two or more elements are not in direct contact with each other, but yet still cooperate or interact with each other.

For the purposes of the description, a phrase in the form “NB” or in the form “A and/or B” means (A), (B), or (A and B). For the purposes of the description, a phrase in the form “at least one of A, B, and C” means (A), (B), (C), (A and B), (A and C), (B and C), or (A, B and C). For the purposes of the description, a phrase in the form “(A)B” means (B) or (AB) that is, A is an optional element.

The description may use the phrases “in an embodiment,” or “in embodiments,” which may each refer to one or more of the same or different embodiments. Furthermore, the terms “comprising,” “including,” “having,” and the like, as used with respect to embodiments of the present disclosure, are synonymous.

Disclosed in various embodiments are swivel couplings referred to herein as Riser Elastic Swivel (RES) joints that may permit a riser or other submerged hull to be rotated with respect to ocean currents. As used herein, “elastic” or “elastic swivel” or similar variations may mean any structure and/or material that includes, allows for, or induces spring like properties and/or that has a resiliency.

Such RES couplings in accordance with various embodiments may be used, for instance, in conjunction with a Boundary Layer Control (BLC) system in order to reduce drag and vortex induced vibration (VIV) of marine drilling risers and other submerged hulls when they are beset by ocean currents. Such BLC systems are disclosed, for example, in U.S. Pat. Nos. 7,108,457, 6,349,664 and 6,148,751, and may be fixed to a lower portion of the riser, which in some embodiments may include a blowout preventer, allowing that the riser, or portions thereof, be variably rotatable about a vertical axis in order to align the BLC system with the direction of ocean currents. Because ocean currents may have any bearing angle relative to the sea floor, in various embodiments, it may be desirable for at least the current-exposed portion of the riser to be rotatable through both clockwise and anti-clockwise angles of up to 180 degrees in order to be adequately aligned to allow the BLC systems to properly function

FIG. 1 illustrates three exemplary configurations of piping flex hoses adapted for use with vertical risers, FIG. 2 illustrates an exemplary RES in both an external view (right side) and a cutaway view (left side), with the RES integrated as the lower part of a specialized riser joint, and FIG. 3 illustrates a detailed view of the two areas of the RES joint that are indicated in FIG. 2, all in accordance with various embodiments. As shown in FIG. 1, a RES 100 may be configured to provide torsional compliance to a marine drilling riser tube 200 about a vertical axis 30 between a first, rotatabely restricted upper portion of a riser and a second, fixed lower portion 2 of the riser. As shown in FIG. 2, in various embodiments, torsional compliance may be provided by an elastic compliance member 4, which may include an annular, compliant stack of composite materials surrounding the lower portion 2 of the riser and thus forming a tube around the lower section. The compliance member 4 may include a plurality of annular resilient rings 5 interleaved by more rigid and noncompliant rings 6, which may be laterally constrained between inner 36 and outer 38 tubular structural walls.

In various embodiments, the elastic compliance member 4 may form a torsionally flexible, tubular spring element impermeably connecting the upper portion 1 of a marine drilling riser to the lower portion 2 of the marine drilling riser or appliance. In various embodiments, the elastic compliance member 4 also may flexibly seal, for example, the hydrostatically pressurized drilling mud inside the riser tube 200, and may prevent it from leaking into the surrounding seawater, which typically is at a lower pressure than that of the depth-adjacent drilling mud.

In various embodiments, the riser tube 200 may carry a tensional load that results from the riser's net buoyancy plus an upward force (top tension) applied by, for example, a drilling vessel, as well as the excess pressure of the drilling mud. Together, these forces may tend to lengthen the riser tube 200. In some embodiments, the compliant element 4 of the RES 100 may serve to resist the riser vertical tension load by means of axial compression on the complaint member 4. In addition, as shown in FIG. 1, in various embodiments, the auxiliary pipelines 32 of the upper 1 and lower 2 marine drilling riser sections may be connected across the torsional swivel element (e.g., compliance member 4) of the RES 100 by one or more flexible hose-pipes 34 disposed around the outer circumference of the riser. Pipes 34 may be used to rout material, such as hydraulic fluid, water, mud and other components to and from, for example, a lower marine riser package (LMRP).

In various embodiments, the upper riser portion 1 may be turned relative to the fixed lower portion 2 against the torsional compliance of the RES 100 by means of a vertical axis moment applied to the top of the first upper riser portion 1 at an elevation location below that of, for example, a heave compensator of the deploying drilling vessel. In various embodiments, the limits of rotation of the first, upper riser portion 1 relative to the second lower riser portion 2 may be about one hundred eighty degrees in either direction.

The RES 100 may be located on the riser 200 such that it does not impede time-consuming riser running and retrieval operations. For instance, in various embodiments, the RES 100 may be positioned either at or near the uppermost part of the LMRP, where a “tiltably” flexible ball-joint and flexibly looped hoses connecting the riser pipe and auxiliary piping may already exist, or immediately above and readily attachable to those structures. In various embodiments where the LMRP may be stored beneath the drill-floor between riser deployments, it may be connected to the lowest riser joint and the lower riser flange 8, where the RES 100 and its associated flexible hoses may pass through the restricted aperture of the rotary.

Current-induced bending moments, with or without the BLC system in operation, may be generally the lowest at the lower riser flange 8 and generally the highest nearer to the surface. Thus, in some embodiments, if the RES 100 were to be placed higher in the riser string, rather than proximate to the LMRP, the RES 100, and particularly its exposed flex-hoses, would be exposed to greater current velocities with resulting additional drag and vibration consequences unmitigated by the BLC system on the riser joints. In various embodiments, a bottom-most location for the RES 100 may not be selected because of the maximal mud pressure inside the riser tube 200 at that location.

In various embodiments, because the lower riser joints may be free of applied buoyancy modules, their diameters may be limited by that of their connecting flanges 44. Those flange diameters may be somewhat less than that of the buoyancy modules, on upper joints so-equipped, which must pass through the rotary (not shown).

A joint-integral elastic rotary connector 46 may be bypassed on its exterior by hard piping 32 from the lower, fixed flange 48 to a level above it where the riser 200 is rotatable, whereupon flexible hose-pipes 34 may be attached.

As shown in FIG. 2, the circumscribing diameter of the hard-piping, with fittings, may be less than the inside diameter of said rotary, for example, about 60 inches. As may be seen in FIG. 1, these hose-pipes 34 may extend upward, with adequate slack for twist, around the rotatable part of the joint to an affixed terminal flange. At and/or above this flange 44, the auxiliary piping may continue in hard pipe. The hose-terminating flange 44 may be, for example, the upper flange of a “pup” joint, or, for example, it may be installed at an adequate intermediate height in a full length joint. In various embodiments, the hose pipes may be constrained close to the riser tube by a girdle of netting or fabric (not shown).

In various embodiments, the riser tube 200 may be “steered” to align with the current by twisting the riser tube 200 against the RES 100 torsionally compliant swivel. In some embodiments, torque may be applied to the riser top, below the heave compensator, by swinging a DP rig while holding the riser tube 200, while in other embodiments, rotation may be accomplished with a tackle on a taut-moored rig, for example.

As illustrated in FIG. 2, the upper riser portion 1 may be in a state of tension, as it is being pulled upward by the drilling rig in order to straighten the riser tube 200 against its tendency to bend when subjected to ocean current-induced drag. The bottom portion 2 of the RES 100 may be fixed to the LMRP (not shown) at the wellhead, by means of a standard bolting flange 24, and may transmit the riser tension thereto. The path for transmission of the riser tension may include the compliance element 4, which may be for example, an annular composite elastomeric column as described above that is compressed vertically by virtue of the pulling tension on the upper riser portion.

In various embodiments, the external environment 3 may be seawater at considerable hydrostatic pressure due to the depth of submergence, which pressure may be substantially less than the pressure of the denser drilling mud in the interior of the riser tube 200. Also shown on the external view is a typical run of “choke & kill” line or hydraulic line hard piping 20. Such piping may be let through the bolting flange 24 at a standard radial location, which is illustrated as smaller than that required to clear the enlarged barrel 2 a of the RES 100, where it contains the torsionally elastic compliance member 4. In embodiments, the pipes 20 may be jogged outward by a pair of elbows 21, for instance to provide clearance. At the top of the barrel 2 a the closure bolting flanges 22 may be notched to accept the passing pipes 20, which may be secured, for instance, by a clamp 23.

FIG. 3 illustrates an enlarged view of the compliant member illustrated in FIG. 2. As described above, compliance member 4 may include an assembly of generally rigid annular rings 6, for instance made of stainless steel or other stiff/rigid, non-corroding material, interleaved between elastomeric (for instance rubber) annular rings 5. Rigid annular rings 6 may serve to stabilize the elastomeric layers/rings 5, which if employed alone, could buckle under the large compressive load applied by the riser tension. Further, the interleaving of the annular flat rings 6 and elastomeric layers 5 may restrain the elastomeric layers 5 against too much radial compression and distortion consequent to the overpressure of the drilling mud relative to the seawater, thereby preventing the compliant member from binding. Further, the interleaving annular flat rings 6 may help to stabilize the elastomeric layers 5 when under large shear, avoiding gross, possibly uneven distortions.

In various embodiments, the interleaving rigid annular rings 6 and compliant layers 5 may be bonded together with a bond strength that may exceed the maximum expected shear stress, which may be caused by the torsional forces, pressure exerted by the drilling mud and/or the seawater. This bond may also help prevent the passage of high pressure mud or seawater through the annular rings. In various embodiments, a somewhat conical, rather than planar shape to interleaving annular rings 6 and complaint layers 5 may also be used. In other embodiments, other geometric configurations may be used.

The rigid annular rings 6 and elastomeric layers 5 may be securely bonded to one another in order to sustain the shear stresses induced by the torque associated with the twisting of the riser tube 200. Additionally, in embodiments, the elastomeric layers 5 may have coves at their inner and outer radius surfaces in the inner and outer radial spaces 11, 12, so that they may not bind when radially expanded under the axial compressive loads associated with riser tension. In embodiments, a large range of relatively friction-free angular operation may thereby be obtained at the cost of somewhat increased vertical compliance. Angular limit stops also may be provided in some embodiments at approximately one-half of a revolution in either direction, in order to prevent over-stressing the elastic compliance members 4 or of the hose pipes above. In various embodiments, the stops may be positioned in space 10 (see FIG. 3.

In various embodiments, the tension in the riser tube 200 may generally be resisted by the compliance member 4, which may be put into a state of vertical-axial compression. In some embodiments, axial (vertical) limit stops (not shown) may also be included to protect the torsionally compliant member 4 against over-compression or extreme tension loads. Such stops may also resist free turning of the riser tube 200 for ocean current alignment, in which instance the riser top-tension applied by the drilling vessel may be temporarily adjusted so that the riser may be turned, and then the desired top-tension may be subsequently restored.

In various embodiments, the upper-most annular flat ring 40 (e.g., terminal ring) may be made fast to the closure flange 17 that is integral with the lower, fixed portion 2 of the RES by virtue of one or more bolts or studs (shown here) 14 to safely transmit the applied torque—related shear loads. Similarly, in various embodiments, the lower-most annular flat ring 42 (e.g., terminal ring) may be made fast to the flange 15 of the vertically and angularly movable upper riser portion 1 in order to transmit the torsional shear loads without slipping or leaking. In various embodiments, the upper- 40 and lower-most 42 annular flat rings may be thicker than the others, and in particular examples, the cylindrical interfaces between the elastic compliance member 4 and its inner 12 and outer 11 riser walls may be lubricated to help minimize friction that may impede torsional-angular motion of the riser tube 200.

In various embodiments clearance between both their inner and outer diameter surfaces and the bounding cylindrical walls inside and outside may exist between the outer periphery of the rigid annular members 6 and compliant rings 5. This clearance may be sufficient to maintain the compliance member 4 in position, and yet resist unnecessary deformation or movement in undesired directions.

Further, where the movable and fixed parts of the RES 100 meet movable parts 7, 8, and 9 while surrounding the elastic compliance member 4, the clearances may not be tight. Therefore, in embodiments, the space 10 and subsequently, the outer radial outer space 11 of the elastomeric component 4 may be subject to the intrusion of drilling mud. Similarly, in embodiments the radial inner space 12 of the elastic compliance member 4 may be subject to intrusion of seawater via the gap 9. As the drilling mud may be at a higher pressure than the surrounding seawater, loss of mud by migration through the various necessary gaps may be blocked in some embodiments by the elastic compliance member 4. In embodiments, a leak-resistant seal may be achieved by the inclusion of seals 13 between the upper 40 and lower 42 terminal rings, and the flanges 17, 15 to which they are fastened. Although O-ring seals are illustrated, other types of seals may be used.

In various embodiments, the seam between the bolted closure flange 17 and the barrel 2 a may be sealed by a gasket or equivalent. By so doing, the elastic compliance member 4 may fulfill its second functional role in the RES system in some embodiments, that of a mud seal. In various embodiments, the presence of high-pressure drilling mud on the exterior cylindrical surface of the elastic compliance member 4, and the presence of lower-pressure seawater on its interior surface may put elastic compliance member 4 into a state of radial compression, which will be apparent to those of skill in the art.

In use, in some embodiments, a riser turning-torque may be applied by the drilling vessel to the top of the riser below the heave-compliant telescoping joint (not shown), which generally may not tolerate torque loads, by way of an opposed pair of lever arms (not shown), hinged and extendable/retractable, the distal ends of which may be adjustably attached to the drilling vessel's structure at a location below the drill floor. In various embodiments, other twisting torque means may alternatively be applied, such as pairs of cables wrapped oppositely about the topmost riser joint on a strengthened spool surface; the shipside ends of said cables being fitted to cumulatively compensate for heave excursions of the drilling vessel. Twisting torque and angular displacement of the riser top regions may be applied by either or both means of rotating the drilling vessel about the riser's vertical axis, the torquing system locked, or by maintaining the vessel's heading while applying a twisting torque and motion take-up to the riser top.

Although certain embodiments have been illustrated and described herein, it will be appreciated by those of ordinary skill in the art that a wide variety of alternate and/or equivalent embodiments or implementations calculated to achieve the same purposes may be substituted for the embodiments shown and described without departing from the scope of the present disclosure. Those with skill in the art will readily appreciate that embodiments in accordance with the present disclosure may be implemented in a very wide variety of ways. This application is intended to cover any adaptations or variations of the embodiments discussed herein. Therefore, it is manifestly intended that embodiments in accordance with the present disclosure be limited only by the claims and the equivalents thereof. 

1. A compliant swivel coupling for accommodating torsional forces induced by axial rotation of a marine drilling riser, comprising: a torsionally compliant member disposed about an external surface of a first portion of a drilling riser, the torsionally compliant member helping to connect the first drilling riser portion to a second drilling riser portion and thereby forming a coupling there between; wherein the torsionally compliant member is adapted to allow the first riser portion to rotate axially relative to the second riser portion; and wherein the torsionally compliant member is adapted to prevent water ingress or drilling mud egress through the coupling.
 2. The swivel of claim 1, wherein the torsionally compliant member comprises a vertical composite elastomeric tube.
 3. The swivel of claim 2, wherein the vertical composite elastomeric tube comprises alternating horizontal layers of metal and elastomer.
 4. The swivel of claim 3, wherein the alternating horizontal layers of metal and elastomer are bonded to one another.
 5. The swivel of claim 4, wherein the layers are substantially conical in shape.
 6. The swivel of claim 1, wherein the torsionally compliant member is configured to resist vertical tension on the riser by resisting axial compression.
 7. The swivel of claim 1, wherein the riser further comprises an auxiliary pipeline, wherein the auxiliary pipeline comprises an upper pipeline portion coupled to the axially rotatable upper drilling riser portion and a lower pipeline portion coupled to the fixed lower drilling riser portion, and wherein the upper pipeline portion is coupled to the lower pipeline portion by a flexible hose-pipe.
 8. The swivel of claim 7, wherein the RES comprises two or more auxiliary pipelines.
 9. The swivel of claim 1, wherein the axially rotatable upper drilling riser portion is configured to rotate axially when a vertical axis moment is applied to a top portion of the axially rotatable upper drilling riser portion.
 10. The swivel ES of claim 9, wherein the axially rotatable upper drilling riser portion is configured to receive the vertical axis moment at an elevation location below that of a heave compensator of a drilling vessel.
 11. The swivel of claim 1, wherein the torsionally compliant member is configured to allow the axially rotatable upper drilling riser portion to rotate approximately 180 degrees in either direction with respect to the fixed lower drilling riser portion.
 12. The swivel of claim 1, wherein the RES is positioned on the drilling riser at a position immediately above a Lower Marine Riser Package (LMRP).
 13. The swivel of claim 12, wherein the RES is positioned on the drilling riser at a position immediately above a lower ball joint associated with the LMRP.
 14. A method of providing axial rotation in a marine drilling riser, comprising: coupling an axially rotatable upper drilling riser portion to a fixed lower drilling riser portion with a torsionally compliant member and forming a coupling there between, wherein the torsionally compliant member allows the upper riser portion to rotate axially relative to the lower riser portion, and wherein the torsionally compliant member is adapted to prevent water ingress or drilling mud egress through the coupling.
 15. The method of claim 14, wherein coupling the axially rotatable upper drilling riser portion to the fixed lower drilling riser portion with a torsionally compliant member comprises coupling the axially rotatable upper drilling riser portion to the fixed lower drilling riser portion with a vertical-axis cylindrical composite elastomeric tube.
 16. The method of claim 15, wherein coupling the axially rotatable upper drilling riser portion to the fixed lower drilling riser portion with a torsionally compliant member comprises coupling the axially rotatable upper drilling riser portion to the fixed lower drilling riser portion with a vertical composite elastomeric tube comprising alternating horizontal layers of metal and elastomeric material.
 17. A marine drilling riser, comprising: an axially rotatable upper drilling riser portion; a fixed lower drilling riser portion, the upper and lower riser portions having a common internal bore and an external surface; a torsionally compliant member disposed about the external surface of the drilling riser and connecting the upper drilling riser portion to the lower drilling riser portion thereby forming a coupling there between, wherein the torsionally compliant member is adapted to allow the upper riser portion to rotate axially relative to the lower riser portion; and wherein the torsionally compliant member is adapted to prevent water ingress or drilling mud egress through the coupling.
 18. The swivel of claim 17, wherein the torsionally compliant member comprises a vertical composite elastomeric tube.
 19. The swivel of claim 18, wherein the vertical composite elastomeric tube comprises alternating horizontal layers of metal and elastomer.
 20. The swivel of claim 19, wherein the alternating horizontal layers of metal and elastomer are bonded to one another.
 21. The swivel of claim 17, wherein the torsionally compliant member is configured to resist vertical tension on the riser by resisting axial compression. 